Within the context of production of crude petroleum, or oil, from subterranean formations, there are various methods for optimizing the extraction of “original oil in place” (OOIP).
The primary method of production of crude petroleum comprises, once the well has been drilled, recovering the crude petroleum by migration of the petroleum from the rock or sand formation, to a well at lower pressure, then pumping it to the surface, via a “producing” well. Primary production is accordingly the least expensive method of extraction. Typically only 10 to 15% of OOIP is recovered. Nevertheless, as the oil is pumped, the pressure decreases and extraction becomes more difficult.
Secondary methods of production are used when the subterranean pressure becomes insufficient to displace the remaining oil. The commonest technique, waterflooding, uses injection wells which force a drive fluid consisting of large volumes of water under pressure into the zone containing the petroleum. During its migration from the zone to one or more producing wells, the injected water entrains a proportion of the petroleum that it encounters. At the surface, the petroleum is separated from the injected water. Waterflooding makes it possible to recover an additional 10 to 30% of OOIP.
When waterflooding reaches the point where production is no longer profitable, a decision must be taken: change of oilfield, or recourse to another phase of exploitation. It is then possible to employ a technique of assisted recovery using waterflooding in which the water contains surfactants and/or polymers. These polymers are used for increasing the viscosity of the drive fluid and thus improve the flushing of the petroleum by the drive fluid. For example, increasing the viscosity of the water by means of viscosity-improving agents, such as partially hydrolyzed polyacrylamides of high molecular weight, is known. However, these acrylic polymers have insufficient stability when the drive fluid has salinity and at application temperatures above 80/100° C.
These surfactants, which are water-dispersible and/or water-soluble, on coming into contact with the petroleum contained in the rock or sand, lower the water/oil interfacial tension, permitting entrainment of the oil trapped in the narrowed pores in the reservoir.
Thus, injection of a drive fluid making it possible both to reduce the water-oil interfacial tension to less than 1 mN/m and to maintain, in the conditions of temperature and salinity of the reservoir, a viscosity of 10 cP at shear of 10 s−1 for a surfactant concentration below 1 wt. %, is known, as described in USA patents US 2007/0107897, US 2007/0142235 and U.S. Pat. No. 7,461,694.
The zwitterionic surfactants and notably the betaines are preferably used on account of their stability in brines. The term zwitterionic describes surfactants having a permanent positive charge regardless of the pH and having a negative charge beyond a certain pH. However, these surfactants can degrade during use at temperatures above 80/100° C. in saline oil reservoirs and the drive fluid can then suffer a loss of its viscosity-improving capacity.
There is therefore still a need for viscoelastic compositions with modified and improved properties, notably:
good stability at relatively high ionic strength, in a medium that is relatively and even very saline with 1, 3, 10 and even up to 20 wt. % of salts, generally alkali-metal and alkaline-earth-metal salts, said medium remaining pumpable after viscosity improvement;
good durability of stability and/or of thickening at relatively high temperature, in the range from 50° C., for example up to 70° C. and even 120° C. and higher, and
a viscosity-improving capacity that is as effective as possible at the lowest contents of viscosity-improving zwitterionic surfactants, and
a combination and/or improved compromise of at least two of these properties.